To prepare saleable petroleum fuels, refiners generally need to satisfy a variety of governmental regulations and industry standards relative to various components and characteristics of the fuel. Sulfur levels and cetane number are two such characteristics commonly monitored during diesel fuel refining. Regarding sulfur content, new requirements for ultra low sulfur diesel (ULSD) typically require less than about 10 wppm sulfur. Regarding cetane numbers, it is generally desired to have a diesel fuel with a cetane number greater than about 40, and in some cases, from about 40 to about 60. A higher cetane number generally correlates to a higher quality diesel fuel.
Current refining processes to achieve both low levels of sulfur and high cetane numbers can be complex, expensive, and require large amounts of high pressure hydrogen. For example, a mild hydrocracking unit, which typically includes a hydrotreating zone and a hydrocracking zone, is one method to produce diesel boiling range hydrocarbons with a reduced level of sulfur from a vacuum gas oil or other feed stream. However, the typical mild hydrocracking unit generally cannot produce diesel meeting the ultra low sulfur requirements with acceptable cetane numbers. In many cases, the product from a common mild hydrocracking unit still has about 100 to about 2000 wppm of sulfur and a relatively low cetane number of about 30 to about 40.
Further processing or increasing the severity of the hydrotreating process to achieve lower levels of sulfur and higher cetane generally over treats the higher boiling components and requires additional high pressure vessels. Overtreated higher boiling components are generally not suitable for subsequent fluid catalytic cracking. Additional high pressure vessels require a large capital investment and are more costly to operate. Moreover, the additional or modified reactors in these units typically incorporate three-phase (gas/liquid/solid catalyst) trickle bed reactors that have large hydrogen requirements in order to maintain a continuous gas-phase throughout the reactors. Increasing the pressure of such units typically also requires a costly, high-pressure recycle gas compressor in order to provide the large hydrogen volumes at higher pressures. For example, a typical high-pressure, three-phase reaction vessel added to a mild hydrocracking unit would require a relatively large portion of the hydrogen recycle gas (up to about 10,000 SCF/B, for instance) to be processed through a high pressure compressor. Such units add further complexity, capital investment, and operating costs to such systems.
A distillate hydrotreating unit, which is designed to process a particular distillate product such as a straight run diesel, is another process to produce diesel boiling range hydrocarbons with a reduced level of sulfur. While the distillate hydrotreating unit can be configured to meet both low sulfur and high cetane specifications, the hydrotreating zone must operate at high pressure, such as about 6.9 MPa (1000 psig) or greater, to achieve both specifications. A three-phase distillate hydrotreating unit at such pressure also requires large hydrogen volumes to maintain the continuous gas-phase. Such large volumes of hydrogen would also need to be processed through a costly recycle gas compressor, and further requires upgrading the reaction vessels to withstand the high pressures.
Two-phase hydroprocessing (i.e., a liquid hydrocarbon stream and solid catalyst) also has been proposed to convert certain hydrocarbonaceous streams into other more valuable hydrocarbon streams in some cases. For example, the reduction of sulfur in certain hydrocarbon streams may employ a two-phase reactor with pre-saturation of hydrogen rather than using a traditional three-phase system. See, e.g., Schmitz, C. et al., “Deep Desulfurization of Diesel Oil: Kinetic Studies and Process-Improvement by the Use of a Two-Phase Reactor with Pre-Saturator,” Chem. Eng. Sci., 59:2821-2829 (2004).
These two-phase systems only use enough hydrogen to saturate the liquid-phase in the reactor. As a result, the reaction systems of Schmitz et al. do not provide for decreasing hydrogen levels due to hydrogen consumption during the reaction process, thus the reaction rate in such systems decreases due to the depletion of the dissolved hydrogen. As a result, such two-phase systems as disclosed in Schmitz et al. are limited in practical application and in maximum conversion rates.
Other uses of liquid-phase reactors to process hydrocarbonaceous streams require the use of diluent/solvent streams to aid in the solubility of hydrogen in the unconverted oil feed. For example, liquid-phase hydrotreating of a diesel fuel has been proposed, but requires a recycle of hydrotreated diesel as a diluent blended into the feed of the liquid-phase reactor. In another example, liquid-phase hydrocracking of vacuum gas oil is proposed, but likewise requires the recycle of hydrocracked product into the feed of the liquid-phase hydrocracker as a diluent.
Because hydrotreating and hydrocracking typically require large amounts of hydrogen to effect their conversions, a large hydrogen supply is still required even if these reactions are completed in liquid-phase systems. As a result, to maintain such a liquid-phase hydrotreating or hydrocracking reaction in such systems and still provide the needed levels of hydrogen, such prior liquid-phase systems require the introduction of additional diluents or solvents to dilute the reactive components of the feed. In such systems, the diluents and solvents provide capacity for a larger concentration of dissolved hydrogen in the stream relative to the now diluted reactive components in the feed to insure adequate conversion rates can occur in the liquid-phase. Larger, more complex, and more expensive liquid-phase reactors are needed in these systems to achieve the desired conversions.
Although a wide variety of process flow schemes, operating conditions and catalysts have been used in commercial petroleum hydrocarbon conversion processes, there is always a demand for new methods and flow schemes that provide more useful products and improved product characteristics. In many cases, even minor variations in process flows or operating conditions can have significant effects on both quality and product selection. There generally is a need to balance economic considerations, such as capital expenditures and operational utility costs, with the desired quality of the produced products.